Alternating sagd injections

ABSTRACT

Methods produce heavy oil with steam assisted gravity drainage. Such methods alternate a traditional steam injection with an injection of a steam-plus-non-condensable gas (such as CO 2  or CO 2 -plus-diluent) mixture. The CO 2 /diluent mixture is soluble in bitumen, leading to a reduction in viscosity of the heavy oil. Additionally, the steam-only injection reduces the accumulation of vapor NCG along the edge of the steam chamber, leading to improved thermal efficiency.

PRIOR RELATED APPLICATIONS

This application is a non-provisional application which claims benefit under 35 USC §119(e) to U.S. Provisional Application Ser. No. 61/897,555 filed Oct. 30, 2013, entitled “ALTERNATING SAGD INJECTIONS,” which is incorporated herein in its entirety.

FEDERALLY SPONSORED RESEARCH STATEMENT

Not applicable.

FIELD OF THE DISCLOSURE

The disclosure generally relates to methods for improving hydrocarbon recovery utilizing alternating steam and steam-plus-additive injections.

BACKGROUND OF THE DISCLOSURE

Canada and Venezuela have some of the largest deposits of a thick, heavy oil called “bitumen.” Bitumen is especially difficult to recover because it is wrapped around sand and clay, forming what is call “oil sands.” Furthermore, the viscosity of bitumen in a native reservoir is high—often in excess of 1,000,000 cP. It will not flow without being stimulated by methods such as the addition of solvent and/or heat.

Many approaches to recovering heavy oils focus on lowering the viscosity through the addition of heat. Commonly used in situ extraction thermal recovery techniques include a number of reservoir heating methods, such as steam flooding or steam drive, cyclic steam stimulation, and Steam Assisted Gravity Drainage (SAGD), but there are also combustion based processes (such as in situ combustion or ISC) and solvent based processes (such as vapor extraction or VAPEX), and combinations of the above.

SAGD is the most extensively used technique for in situ recovery of bitumen resources in the McMurray Formation in the Alberta Oil Sands and other reservoirs containing viscous hydrocarbons. FIG. 1 illustrates the typical SAGD system. In a typical SAGD, two horizontal wells are vertically spaced by 4 to 10 meters (m). The production well is located near the bottom of the pay and the steam injection well is located more or less directly above and parallel to the production well. In SAGD, steam is injected continuously into the injection well, where it rises in the reservoir and forms a steam chamber.

In order to establish initial communication between the wells, a startup period is employed where steam is circulated for 3 to 5 months in each well (both production and injection wells) to establish fluid communication between well pairs. However, this 3 to 5 month startup time increases the overall cost of SAGD because of the amount of steam required and the delay before oil production can begin. Decision makers may limit projects available for SAGD production because of this added cost.

Once fluid communication is established, the steam is injected only into injection wells. With continuous steam injection, the steam chamber will continue to grow upward and laterally into the surrounding formation. At the interface between the steam chamber and cold oil, steam condenses and heat is transferred to the surrounding oil. This heated oil becomes mobile and drains, together with the condensed water from the steam, into the production well due to gravity segregation within the steam chamber.

This use of gravity gives SAGD an advantage over conventional steam injection methods. SAGD employs gravity as the driving force and the heated oil remains warm and movable when flowing toward the production well. In contrast, conventional steam injection methods displace oil to a cold area where its viscosity increases and the oil mobility is again reduced.

Operating the injection and production wells at approximately reservoir pressure eliminates the instability problems that plague all high-pressure steam processes and SAGD produces a smooth, even production that can be as high as 70% to 80% of oil in place in suitable reservoirs. The process is relatively insensitive to shale streaks and other vertical barriers to steam and fluid flow because, as the rock is heated, differential thermal expansion causes fractures in it, allowing steam and fluids to flow through. This allows recovery rates of 60% to 70% of oil in place, even in formations with many thin shale barriers.

Thermally, SAGD is twice as efficient as the older cyclic steam stimulation (CSS) process, and it results in far fewer wells being damaged by high pressure. Combined with the higher oil recovery rates achieved, this means that SAGD is much more economical than pressure-driven steam processes where the reservoir is reasonably thick.

Although quite successful, SAGD does require enormous amounts of water in order to generate a barrel of oil. Some estimates provide that 1 barrel of oil from the Athabasca oil sands requires on average 2 to 3 barrels of water, although with recycling the total amount can be reduced to 0.5 barrel. In addition to using a precious resource, additional costs are added to convert those barrels of water to high quality steam for down-hole injection. Therefore, any technology that can reduce water or steam consumption has the potential to have significant positive environmental impact and cost savings.

In U.S. Pat. No. 6,230,814, an expanding solvent SAGD (ES-SAGD) method is described that involves the co-injection of low concentrations of a hydrocarbon solvent with steam. The selected solvent evaporates and condenses at the same conditions as the water phase, so that it will condense with the steam and dilute the oil. Use of a solvent reduces water requirements and fuel consumption as well as greenhouse gas emissions, and the solvent can sometimes be recovered and reused. However, much research has to be done before ES-SAGD becomes an economically viable alternative to SAGD.

Additionally, U.S. Pat. No. 6,230,814 is focused on hydrocarbon additives such as C1-C25 hydrocarbons, which condense at the chamber boundaries and function to dilute the oil, thus mobilizing it. It does not use non-hydrocarbon and non-condensable additives (e.g. CO2, N2, etc.), and therefore, the mechanisms and impacts are different than the inventive method.

In most SAGD operations, the steam is generated at a central processing facility (CPF) and conveyed to the wellpads, where it is injected into the SAGD reservoirs. An alternate approach is to locate the steam generating devices at the wellpads and convey the required water, fuel, and oxidant to the steam generators from the CPF.

One example of a wellpad steam generator is the Direct Steam Generator (DSG) concept. In DSG-SAGD (see US20130068458), fuel is burned at the wellpad in the presence of water to produce a stream of high-pressure, high temperature steam and approximately 10-12% CO2 that is injected directly into SAGD injection wells. DSG-SAGD offers many advantages over other steam generation technology such as higher efficiency and being CO2 capture ready. Additionally, DSG-SAGD has less water consumption for an equivalent amount of oil recovery.

Research has shown, however, that the disadvantage of co-injecting CO2 or other solvents with steam is the accumulation of the non-condensable gas in the upper part of the steam chamber, thus inhibiting steam chamber growth. The gaseous additive is also thought to accumulate at the side boundary of the steam chamber because steam not dissolved in the bitumen condenses there. Additionally, some of the accumulated additive is from the refluxing of the dissolved CO2 or solvent from the liberated liquid phase hydrocarbon mixture.

For example, the solubility of CO2 in bitumen is temperature-dependent. FIG. 2 displays a simulated temperature profile of a vertical cross section of the steam chamber development during the DSG-SAGD process in a conventional well pair configuration. The black arrows show the flux vectors of the gas phase and the white lines are the streamlines of the gas phase from the injector to the producer. At normal steam chamber temperatures (˜200-250° C.), very little CO2 is capable of being dissolved, but the solubility increases at the lower temperatures, such as those along the boundary of the steam chamber. Thus, the flux vectors are pointed towards the outer gas steam line along the 110-140° C. region. The non-condensable gas, in this case CO2, has the highest solubility in the steam chamber interface and reduces the bitumen mobility at that location.

The temperature increases near the injector/producer region, which causes the CO2 to effervesce as the CO2-rich bitumen along the boundary drains to the production well. The effervescing CO2 moves upward, resulting in the refluxed CO2 accumulating along the edge of the steam chamber.

FIG. 3 displays the gas mole fraction of CO2 of the steam chamber in FIG. 2. As expected, a considerable amount of CO2 accumulates at the edge of the steam chamber. This accumulation ultimately leads to a decrease in hydrocarbon recovery. FIG. 4 compares the oil production rates in SAGD and DSG-SAGD with CO2 accumulation. The oil production rate for DSG-SAGD is much lower than SAGD for the first 10 years and never fully reaches the oil production seen in traditional SAGD.

In addition to lower hydrocarbon recovery, an accumulation of CO2 and solvents along the steam chamber has adverse effects on reduced energy consumption. First, the accumulated CO2/solvent acts as a thermal insulting blanket and impairs the transport of heat from steam to bitumen. Second, due to the partial pressure effect, the temperature of the drainage interface decreases and the oil that drains along the boundary becomes less mobile. Third, the gas saturation increases as a direct result of gaseous CO2/solvent accumulation at the drainage interface, which decreases the effective permeability to oil. All three mechanisms affect the growth of the steam chamber. Thus, more steam has to be injected, offsetting any potential energy savings.

Thus, what is needed is an improved SAGD method that increases hydrocarbon recovery and steam chamber efficiency while increasing the economic viability of the SAGD and other steam based methods. Ideally, such improvement can be used with any derivative steam or SAGD processes, too.

SUMMARY OF THE DISCLOSURE

The present disclosure relates to improved injection methods that maximize oil recovery while minimizing energy and water consumption. In particular, the improvement is the alternation of a co-injection of steam mixed with a non-condensable gas (NCG) such as CO₂ and optionally including a diluent with the traditional steam injection.

Co-injections of steam with a NCG and/or a diluent are well known SAGD processes. However, embodiments of the present improvement include the cyclic use of a steam injection after each co-injection. This improvement addresses the issue of accumulation of the NCG along the steam chamber. The second steam-only injection unexpectedly increases the dissolution of the accumulated NCG in the hydrocarbon. Thus, most, if not all, of the accumulated NCG is dispersed in the hydrocarbon. By reducing the NCG accumulation along the edge of the steam chamber, improvements in steam chamber formation and growth and increased hydrocarbon production with less water and energy consumption is seen.

A steam-only cycle follows each cycle of co-injection. Its length is adjustable and can be lengthened to eliminate all accumulated NCG, but the steam injection time may be about twice the co-injection time. As soon as the accumulated NCG is eliminated, the co-injection cycle can start again. The alternating steam and non-condensable cycles may continue until blow down.

The steam can be produced using conventional steam generation devices, such as an OTSG. In certain embodiments, the NCG is combined with the steam before injection into the injector, in others it is injected simultaneously, but not mixed prior to injection. In certain other embodiments, a direct steam generator (DSG) can be substituted in place of a traditional steam generator. DSG outputs the steam and NCG as a single combined stream, so a separate steam source may be needed for the steam-only injection. Nonetheless, by taking advantage of existing sources of flue gas, green house gases emissions may be reduced by providing a useful application of existing flue gas rather than venting the flue gas to the atmosphere.

The alternating injection method can be used with all thermal injection hydrocarbon recovery processes and SAGD derivatives. However, this method is preferably used with SAGD, DSG-SAGD, and expanding solvent SAGD (ES-SAGD), VAPEX, CSS, SD, and the like.

Conventional SAGD field configurations can be used with the present improvement. One or more horizontal injector and one or more horizontal producer well pairs separated vertically by 2-10 meters, preferably, 3-7 meters, and most preferable 4-5 meters can be used with the current improvement. Any well length can be used with the presently disclosed improvement. Generally, horizontal wells can be from a few meters to a few kilometers long.

Novel well configurations can also be used, such as the fish-bone wells and radial wells, recently described in patent applications by ConocoPhillips. In these variations, the wells are not vertically paired as in traditional SAGD, but nonetheless the wells are positioned to allow gravity drainage from a vertical steam chamber and they can be considered SAGD variants. See 61/825,945 titled RADIAL FISHBONE SAGD, filed May 21, 2013, and 61/826,329, titled FISHBONE SAGD, filed May 22, 2013.

A variety of NCG can be co-injected with the steam. A NCG gas as used herein may come from chemical or petroleum processing units (such as distillation columns or steam ejectors) and remains gaseous under reservoir conditions—NCG's consist mostly of nitrogen, carbon dioxide, or other gaseous materials. Examples of suitable NCG include, but are not limited to, CO2, CO, N2, He, H2, O2, flue gas, air and the like. A preferred NCG includes CO2, which is a waste gas and contributes to global warming.

Preferably, the amount of NCG added to the steam is in the range of from about 0.1% to about 15% liquid volume of the fluid composition. More preferably, the amount of is in the range of from about 1-12% or 2-10% liquid volume of the fluid, but may be in the 10-12% range when a DSG unit is employed.

Diluent is also an option and can be added to the NCG, thus further improving heavy oil mobility. Diluents are well known in the art, and can be as described in the art, including but not limited to methane, ethane, propane, butane, pentane, hexane, heptane, octane, nonane, decane, undecane, dodecane, tridecane, tetradecane, kerosene, naphtha and combinations thereof. Diluents will dissolve into the heavy oil, diluting it and increasing its mobility. Diluent can be used at 0-25% liquid volume, or 5-20%. One preferred diluent is at least 75% C5+ hydrocarbons, or 80% or 805% C5+ hydrocarbons. Diluents can also be varied over time, e.g., starting with a lighter hydrocarbon, then switching to a heavier hydrocarbon, or the reverse.

In one aspect, the improvement is the alternation of the steam-only injection with a steam and non-condensable gas and a diluent co-injection (3 component stream). Ideally, the chosen diluent mimics the evaporation/condensation pattern of water at SAGD operation temperatures and has good solubility in bitumen at the optimum operating temperature for SAGD. This similarity is necessary because when an additive's evaporation temperature is greater than the steam temperature, the additive will begin to condense before steam condensation occurs. Likewise, when the additive's evaporation temperature is less than the steam temperature, steam will begin to condense before additive condensation occurs. Thus, selection of a diluent having an evaporation temperature within the specified temperature range of the steam temperature at a predetermined operating pressure results in increased hydrocarbon mobility in the reservoir to the producing well and is paramount to the described improvements.

In another aspect, the improvement is the alternation of the steam injection with a steam-and-CO2 co-injection. The CO2 and steam may be produced by direct combustion of fuel and oxygen in a Direct Steam Generation process. Generally, the temperature of the steam and CO2 mixture is approximately 250-300° C. and injected at approximately 60 bars.

The steam-and-NCG co-injection usually follows whatever process is used to establish fluid communication between the injector and producer wells, but it can also follow initial production processes, such as DS or CSS. Most often fluid communication is established by steam injection in the injector, the producer, or both injector and producer. Additionally, the wells can be closed for 2-5 months to encourage the fluid communication. Other methods to establish fluid communication can also be used.

Next, mixed steam and NCG or separate steam and NCG are co-injected for a period of time, and as noted above, a diluent can be used in addition to the NCG (in addition some NCG may also function as diluents). A steam-only injection follows each co-injection, and helps with the dissolution of the accumulated NCG on the outer boundaries of the steam chamber into the hydrocarbons. As used herein, steam-only in some embodiments to pure steam or steam without NCG but with other constituents such as diluents. The order can also be reversed, but the process preferably starts with steam and then the steam and non-condensable gas co-injection, otherwise, the non-condensable gas may impair the growth of the start-up steam chamber.

The invention include any one or more of the following embodiments, in any combinations:

-   -   An improved method for steam recovery of heavy oil from a         formation, the method involving mobilizing heavy oil with         steam-plus-non-condensable-gas (NCG), and recovering said         mobilized heavy oil, the improvement comprising alternating an         injection of steam with the co-injection of steam-plus-NCG and         recovering mobilized heavy oil, wherein a cumulative         steam-to-oil ratio is reduced as compared with steam-plus-NCG         co-injection alone.     -   An improved method for steam recovery of heavy oil from a         formation, the method involving mobilizing heavy oil with an         injection of steam-plus-NCG and recovering said mobilized heavy         oil, the improvement comprising alternating an injection of         steam with a co-injection of steam-plus-NCG, and recovering         mobilized heavy oil, wherein a rate of heavy oil production is         higher as compared with steam-plus-NCG co-injection alone.     -   A method for steam recovery of heavy oil as described herein,         which is a steam assisted gravity drainage (SAGD), Expanding         Solvent SAGD, Vapor Extraction (VAPEX), Steam And Gas Push         (SAGP); cyclic steam stimulation (CCS), and combinations and         variations thereof.     -   A method for enhancing the recovery of hydrocarbons from a heavy         oil reservoir comprising providing one or more injection wells         that intersect a heavy oil reservoir; providing one or more         production wells that intersect the heavy oil reservoir and         wherein injection wells are in fluid communication with adjacent         production wells; co-injecting steam-plus-NCG into one or more         injection wells for a first predetermined time; injecting steam         into said one or more injections wells for a second         predetermined time; producing hydrocarbons from said one or more         production wells; and repeating the cycle.     -   A method for enhancing the recovery of heavy oil comprising the         steps of providing one or more injection wells in a heavy oil         reservoir; providing one or more production wells in the heavy         oil reservoir, wherein the one or more injection wells and the         one or more production wells are paired to allow a gravity         drainage process and wherein paired wells are in fluid         communication with each other; producing a mixture of steam and         10-12% NCG using a Direct Steam Generation combustion process;         co-injecting said steam and 10-12% NCG mixture into one or more         injections wells for a predetermined amount of time; producing a         steam stream using a steam generator; injecting said steam         stream into said one or more injection wells for a second         predetermined time; producing hydrocarbons from the one or more         production wells; and repeating the injection cycles.     -   A method where the NCG comprises CO2 or CO2 and a diluent, or         the NCG comprises CO2, CO, H2, He, flue gas, N2, air, or         combinations thereof.     -   A method where the NCG is chosen from the group consisting of         CO2, N2, and flue gas and said diluent is chosen from         hydrocarbon solvents having 1 to 12 carbons, naphtha, diesel,         aliphatic hydrocarbons with 6-30 carbons, and aromatic solvents         such as toluene, benzene, xylene, or any combination thereof, or         the diluent is 85% C5+ hydrocarbons.     -   A method of decreasing heavy oil recovery operation costs,         comprising alternating co-injections of steam-plus-NCG with         injections of steam-only in a heavy oil reservoir; and producing         heavy oil from said reservoir; wherein an overall cumulative         steam to oil ratio is reduced as compared with a steam-plus-NCG         co-injection used alone, or an overall oil production rate is         increased as compared with a steam-plus-NCG co-injection used         alone, or both results are achieved.     -   A method for recovering petroleum from a formation, wherein at         least one injection wells and at least one production well are         in fluid communication with said formation and with each other,         comprising: introducing a first gaseous mixture into said         injection well for a first predetermined time, wherein said         first gaseous mixture comprises steam-plus-NCG; introducing a         second gaseous mixture into said injection well for a second         predetermined time, wherein said second gaseous mixture         comprises steam; recovering a fluid comprising petroleum from         said production well; and repeating the steps.     -   A method wherein the injection well and said production well are         horizontal parallel wells, and wherein said injection well is         disposed 3-10 meters above said production well.

As used herein, “increased hydrocarbon mobility” means that the hydrocarbon has decreased viscosity and/or reduced interfacial tension, as compared with a hydrocarbon produced using only steam under substantially similar formation conditions.

As used herein, “% liquid volume” of a fluid composition means the liquid volume of additive divided by the sum of the liquid volume of additive and the liquid volume of steam in the fluid composition. Determining the liquid volume of a fluid composition is well known to those skilled in the art. For example, the flow rate of steam can be measured, using an orifice meter, and the equivalent liquid volume at the operating pressure can be determined accordingly. Likewise, an additive can be delivered at a predetermined flow rate through a solvent injection pump to correspond to a predetermined liquid volume at the operating pressure.

As used herein, “non-condensable gas” means a gas that remains in vapor phase under the operating conditions. Of course, since the pressure and temperature of the well can vary within a substantial range, what might normally not be considered a NCG under surface conditions may still be a NCG under reservoir conditions.

As used herein, “fluid communication” means that the mobility of either an injection fluid or hydrocarbon fluid in the reservoir, having some effective permeability, is sufficiently high so that such fluids can be produced at the producing wellbore under some predetermined operating pressure. “Fluid communication” between two wells mans that a fluid can travel from one to the other.

As used herein, the terms “heavy oil” and “bitumen” are used interchangeably to denote hydrocarbons with low viscosity and difficult recovery.

The term “providing” herein is meant to both direct and indirect methods of obtaining access to an object. Thus “providing a well” includes both drilling a new well, as well as using or retrofitting existing wells.

The word “co-injection” refers to different materials being injected into a well at the same time, but the materials are not necessarily premixed and can be separately injected. They can also be pre-mixed and injected in a single stream.

The term “steam” as used herein refers to water vapor or a combination of liquid water and water vapor. It is understood by those skilled in the art that steam may additionally contain trace elements other than water vapor and/or other impurities. The temperature of steam can be in the range of from about 150° C. to about 350° C. However, the required steam temperature is dependent on the operating pressure, which may range from about 100 psi to about 2,000 psi (about 690 kPa to about 13.8 MPa), as well as on the in situ hydrocarbon characteristics and ambient temperatures.

By “steam-only” we mean that no NCG has been added thereto.

As used herein “wellpads” is defined as a relatively flat work area on the earth surface, and is used for well-drilling and oil production.

The term “C5+” hydrocarbons as used herein means that the majority of the hydrocarbons have at least 5 carbons, but 100% purity is not required. C5+ includes C5-C12 hydrocarbons, but more preferably include C5-C8 or C5-C6.

The use of the word “a” or “an” when used in conjunction with the term “comprising” in the claims or the specification means one or more than one, unless the context dictates otherwise.

The term “about” means the stated value plus or minus the margin of error of measurement or plus or minus 10% if no method of measurement is indicated.

The use of the term “or” in the claims is used to mean “and/or” unless explicitly indicated to refer to alternatives only or if the alternatives are mutually exclusive.

The terms “comprise”, “have”, “include” and “contain” (and their variants) are open-ended linking verbs and allow the addition of other elements when used in a claim.

The phrase “consisting of” is closed, and excludes all additional elements.

The phrase “consisting essentially of” excludes additional material elements, but allows the inclusions of non-material elements that do not substantially change the nature of the invention.

The following abbreviations are used herein:

ABBREVIA- TION TERM CO₂ Carbon Dioxide CSS Cyclic steam stimulation DSG-SAGD Direct Steam Generation-Steam Assisted Gravity Drainage ES-SAGD Expanding Solvent-Steam Assisted Gravity Drainage ISC In situ combustion NCG non-condensable gas OTSG Once-through steam generator SAGD Steam Assisted Gravity Drainage SAGP Steam assisted gas push SAP Solvent assisted process SD Steam drive VAPEX Vapor extraction process

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic of a steam-assisted gravity drainage (SAGD) system.

FIG. 2 displays a simulated temperature profile of a vertical cross section during the DSG-SAGD process with conventional well pair configuration.

FIG. 3 displays a simulated profile of the gas mole fraction of CO2 during the DSG-SAGD process with conventional well pair configuration.

FIG. 4 is a comparison of the oil production rates in SAGD and DSG-SAGD.

FIG. 5 displays a simulated profile of the gas mole fraction of CO2 during an alternating steam and steam/CO2 DSG-SAGD injection with conventional well pair configuration.

FIG. 6 displays a simulated profile of the gas mole fraction of CO2 during steam/CO2 cycle in one embodiment of the present invention.

FIG. 7 is a comparison of the oil production rates in SAGD, DSG-SAGD with continuous co-injection of steam and CO2 and DSG-SAGD with alternating injections per one embodiment of the present invention.

FIG. 8 is a comparison of the thermal efficiency in SAGD, DSG-SAGD with continuous co-injection of steam and CO2 and DSG-SAGD with alternating injections per one embodiment of the present invention, wherein the thermal efficiency is based on the cumulative steam oil ratio.

DETAILED DESCRIPTION

The disclosure provides a novel improvement of steam recovery methods that maximizes hydrocarbon recovery while minimizing energy and water consumption, especially solvent assisted methods. Specifically, the improvement addresses the accumulation of NCGs, co-injected with steam, at the edge of the steam chamber. The improvement is based on the theory that minimizing or eliminating the accumulation of NCG co-injectants will allow the steam chamber to grow and, thus, improve hydrocarbon recoveries with minimal energy and water usage.

In the present disclosure, a steam-plus-additive injection is alternated with a steam injection to minimize the accumulation of the additive. As such, less steam is needed to recover a similar amount of hydrocarbon as traditional SAGD methods. Because SAGD and other steam based recovery methods are energy intensive, any decrease in the amount of steam that is used to produce a unit of hydrocarbons is economically advantageous.

The method is specifically exemplified herein with SAGD and with DSG-SAGD methods, but can advantageously be applied to various steam based methods and may precede or follow other non-steam based methods.

The present invention is demonstrated with respect to the following experiments. However, this is exemplary only, and the invention can be broadly applied to all steam based hydrocarbon recovery techniques and can utilize gaseous CO₂ or other NCGs and/or diluents as a co-injectant with the steam.

Experiment 1

A traditional DSG-SAGD with alternating injections of steam and steam mixed with CO₂ was simulated using a numerical simulator such as CMG-STARS to evaluate the potential benefits of the alternating injections. The simulation was modeled after an Athabasca oil sands reservoir of 100 meters in width by 30 meters in height by 850 meters in length. Two (850 m long) horizontal wells were placed near the bottom (producer) and in the middle (injector) of the reservoir, separated by 5 m in the vertical direction. The lower horizontal well was placed 1 m above the bottom of the oil bearing sands. Initially, a pre-heating period of 90 days was used to heat the region between the wells by circulating steam and CO₂ in both the injection and production wells (similar to field pre-heating for SAGD).

The temperature of the steam injection was 250° C. and the temperature of the steam and 10 wt % CO2 mixture was 245° C. and injected at 40 bars. The fuel and oxygen were 10° C. when delivered to the DSG. An expected DSG heat loss of 2% was also factored into the simulation.

The steam and CO2 co-injection was first and it established the steam chamber. FIG. 5 displays the simulated mole fraction profile of the CO2 during the steam and CO2 injection cycle. Some of the CO2 was dissolved in the bitumen and reduced the viscosity. But, as expected, the greatest amount of CO2 accumulated was on the outer boundary of the steam chamber between the injector and producer well. The mole fraction of CO2 decreased towards the producer well and was almost nonexistent near the injector well. This is due to the temperature dependence of the CO2 solubility—the solubility of CO2 in bitumen decreases at higher temperatures. Higher temperatures are found near the injector and producer wells, which means that smaller amounts of CO2 are being dissolved in the bitumen in these locations. Additionally the CO2 seems to accumulate in the lower temperature regions found near the outer edge of the steam chamber.

As the bitumen flows towards the producer well, some gaseous CO2 is released, or refluxed, from the bitumen and moves to upward towards cooler temperatures found near the edge of the steam chamber. The rest of the CO2 remains dissolved in the bitumen and is produced with the less viscous hydrocarbons. During the entire steam/CO2 injection, gaseous, non-condensable CO2 accumulated along the edges of the steam chamber, thus blanketing the chamber and insulating it.

The steam-plus-CO2 co-injection is then alternated with a steam-only injection in a second simulation. The steam-only injection allows the gaseous, accumulated CO2 to further dissolve into the bitumen and be produced through the production well. FIG. 6 displays the gas mole fraction profile of CO2 at the end of a steam-only cycle. First, the shape of the CO2 profile is much different after the steam-only cycle. Much less CO2 is accumulated at the edge of the steam chamber, with the majority being located near the injection well where higher temperatures are found. Thus, the steam-only injection decreases the accumulation of CO2 by increasing the amount dissolved in the bitumen. The mole fraction of CO2 is less than 0.1 near the producer well.

Ideally, the length of the steam-only injection can be modified to completely eliminate the CO2 accumulation. This parameter will depend on the characteristics of the reservoir and the viscosity of the hydrocarbons being produced. In the simulation, we alternated steam injection for 12 months and DSG injection for 6 month. For the modeled reservoir conditions, this allowed almost all of the CO2 to be dissolved and dispersed in the heavy oil. The cycle lengths, slug sizes are parameters that need to be optimized for different reservoirs under different conditions, but the simulation provided one example of a suitable time, and a two to one (steam to steam-plus-NCG) seems to be generally suitable, although the cycles could vary from 1:1 to 3:1.

Experiment 2

A DSG-SAGD with alternating injections was compared with traditional SAGD and DSG-SAGD using continuous co-injection of steam and CO₂. The SAGD and DSG-SAGD simulations used the same configuration and parameters as the simulation in Experiment 1.

FIG. 7 shows the comparison of the oil production rates expected for these three processes. Initially, the traditional SAGD produces higher amounts of oil, but then begins to level off. It should be noted that a much greater water and energy consumption is necessary for SAGD. Thus, the improved oil production rates are offset by the high cost of the traditional SAGD process.

Comparing the two DSG-SAGD processes, the alternating injection (dashed line) has a higher oil production rate than the continuous co-injection process. The difference can be attributed to the increased CO₂ dissolution in the bitumen during the steam-only phase of injection in the alternating injection process. More CO₂ dissolution means less CO₂ accumulating and retarding the growth of the steam chamber and a lower bitumen viscosity, resulting in improved oil production.

Additionally, the thermal efficiency of the alternating injection DSG-SAGD is also greater than in a continuous co-injection process (see FIG. 8). The accumulation of NCG on the chamber walls acts as a thermal insulating blanket around the steam chamber and prevents the effective transport of heat from the steam to the bitumen. Thus, the more CO₂ being dissolved into the bitumen, the less insulating effect, and the greater the thermal efficiency.

Therefore, alternating steam-only and steam-plus-NCG co-injection improved productions rates and reduced steam use as compared to a straight steam-NCG co-injection alone.

The following references are incorporated by reference in their entirety for all purposes.

-   Butler, R. M., “Thermal Recovery of Oil & Bitumen”, Chapter 7:     “Steam-Assisted Gravity Drainage”, Prentice Hall, (1991). -   US20130068458 Heat recovery method for wellpad SAGD steam generation -   US20120312534 Enhanced hydrocarbon recovery through gas production     control for noncondensable solvents or gases in SAGD or ES-SAGD     operations -   U.S. Pat. No. 6,230,814 Process for enhancing hydrocarbon mobility     using a steam additive -   U.S. Pat. No. 8,387,691 Low pressure recovery process for     acceleration of in-situ bitumen recovery -   U.S. Ser. No. 14/227,826 titled RADIAL FISHBONE SAGD, filed May 27,     2014. -   U.S. Ser. No. 14/173,267, titled FISHBONE SAGD, filed May 22, 2013. 

What is claimed is:
 1. A method of enhancing recovery of hydrocarbons from a heavy oil reservoir, comprising: a) providing an injection well that intersects the heavy oil reservoir; b) providing a production well that intersects the heavy oil reservoir, wherein the injection well is in fluid communication with the production well; c) co-injecting steam and a non-hydrocarbon non-condensable gas (NCG) into the injection well for a first time; d) injecting steam without the NCG into the injection well for a second time subsequent to the first time; e) producing hydrocarbons from the production well; and f) repeating steps c and d.
 2. The method of claim 1, wherein the injection and production wells are paired to allow a gravity drainage process, the co-injecting uses a mixture of the steam with 10-12 percent by weight of the NCG produced in a direct-steam-generator, and the injecting of the steam uses output from a steam generator having exhausted flue gas.
 3. The method of claim 1, wherein said NCG comprises CO₂.
 4. The method of claim 1, wherein said NCG comprises CO₂ and is further co-injected with a diluent.
 5. The method of claim 1, wherein the steam and NCG is further co-injected with a diluent, and wherein said NCG contains at least one of CO₂, CO, He, H₂ and N₂, and said diluent is chosen from hydrocarbon solvents having 1 to 30 carbons.
 6. The method of claim 1, wherein said injection well and said production well are horizontal parallel wells and said injection well is disposed 3-10 meters above said production well.
 7. The method of claim 1, wherein said NCG is chosen from a group consisting of CO₂, CO, N₂, H₂, He, air, and flue gas.
 8. The method of claim 1, wherein the steam and NCG is further co-injected with a diluent that is 85% C5+ hydrocarbons.
 9. The method of claim 1, wherein said NCG comprises CO₂ and is further co-injected with a diluent that includes C1-C8 hydrocarbons.
 10. The method of claim 1, wherein the injecting of the steam in step d without introducing additional non-condensable constituents along with the producing in step e depletes accumulation of the NCG in the reservoir.
 11. The method of claim 1, wherein a ratio of first time/second time is between 1:1 and 3:1.
 12. The method of claim 1, wherein a ratio of first time/second time is 2:1.
 13. An improved method for steam recovery of heavy oil from a formation, the method involving mobilizing heavy oil with steam-plus-non-condensable-gas (NCG), and recovering said mobilized heavy oil, the improvement comprising alternating an injection of steam lacking the NCG with co-injection of steam-plus-NCG and recovering mobilized heavy oil, wherein the NCG is a non-hydrocarbon and a cumulative steam-to-oil ratio is reduced as compared with steam-plus-NCG co-injection alone or a rate of heavy oil production is higher as compared with steam-plus-NCG co-injection alone.
 14. The method of claim 13, wherein said method for steam recovery of heavy oil is steam assisted gravity drainage (SAGD), Expanding Solvent SAGD, Vapor Extraction (VAPEX), Steam And Gas Push (SAGP); cyclic steam stimulation (CCS), and combinations and variations thereof.
 15. The method of claim 13, wherein said NCG comprises CO₂.
 16. The method of claim 13, wherein said NCG comprises CO₂ and is further co-injected with a diluent.
 17. The method of claim 13, wherein the steam and NCG is further co-injected with a diluent, and wherein said NCG contains at least one of CO₂, CO, He, H₂ and N₂, and said diluent is chosen from hydrocarbon solvents having 1 to 30 carbons.
 18. The method of claim 13, wherein said NCG is chosen from a group consisting of CO₂, CO, N₂, H₂, He, air, and flue gas.
 19. The method of claim 13, wherein the steam and NCG is further co-injected with a diluent that is 85% C5+ hydrocarbons.
 20. The method of claim 13, wherein said NCG comprises CO₂ and is further co-injected with a diluent that includes C1-C8 hydrocarbons. 